Natural gas is typically recovered from wells drilled into underground reservoirs. It usually has a major proportion of methane, i.e., methane comprises at least 50 mole percent of the gas. Depending on the particular underground reservoir, the natural gas also contains relatively lesser amounts of heavier hydrocarbons such as ethane, propane, butanes, pentanes and the like, as well as water, hydrogen, nitrogen, carbon dioxide, and other gases. A typical analysis of a natural gas stream to be processed in accordance with this invention would be, in approximate mole percent, 89.2% methane, 4.9% ethane and other C2 components, 2.6% propane and other C3 components, 0.4% iso-butane, 1.3% normal butane, and 0.6% pentanes plus, with the balance made up of nitrogen and carbon dioxide. Sulfur containing gases are also sometimes present.
Most natural gas is handled in gaseous form. The most common means for transporting natural gas from the wellhead to gas processing plants and thence to the natural gas consumers is in high-pressure gas transmission pipelines. In a number of circumstances, however, it has been found necessary and/or desirable to liquefy the natural gas either for transport or for use. In remote locations, for instance, there is often no pipeline infrastructure that would allow for convenient transportation of the natural gas to market. In such cases, the much lower specific volume of liquefied natural gas (LNG) relative to natural gas in the gaseous state can greatly reduce transportation costs by allowing delivery of the LNG using cargo ships and transport trucks.
A relatively recent concept for commercializing natural gas from remote locations is to install a liquefaction plant on an offshore platform or on a ship (commonly referred to as floating LNG or FLNG) to allow moving the facility to another location when the gas reservoir is depleted. Deck space is at a premium for both of these, because each increment of deck space requires a very large quantity of supporting structure (and hull volume in the case of FLNG). As a result, great emphasis is placed on minimizing the “footprint” of each processing step in order to minimize the investment cost and thereby maximize the number of gas reservoirs in remote locations that can be economically produced.
For remote locations such as those contemplated here, recovery of the various hydrocarbons heavier than methane as separate products is generally not economically viable since there is usually no means of transporting and selling the resultant hydrocarbon product streams. Instead, to the largest extent possible, these heavier hydrocarbons are liquefied along with the methane and sold as part of the LNG product. However, some degree of heavier hydrocarbon removal is often required prior to liquefying the natural gas because there are usually limitations on the heating value of the re-vaporized gas when it is subsequently distributed from the LNG receiving terminal. In addition, hydrocarbons heavier than C5 or C6 (particularly aromatic hydrocarbons) generally must be removed upstream of the liquefaction step to avoid plugging inside the liquefaction plant caused by freezing of these heavier hydrocarbons. For these reasons, it is typical to include a processing step to remove these hydrocarbons (“heavy ends removal”) before liquefying the natural gas.
Available processes for removing these heavier hydrocarbons include those based upon cooling and refrigeration of gas, oil absorption, and refrigerated oil absorption. Additionally, cryogenic processes have become popular because of the availability of economical equipment that produces power while simultaneously expanding and extracting heat from the gas being processed. Depending upon the pressure of the gas source, the richness (ethane, ethylene, and heavier hydrocarbons content) of the gas, and the desired end products, each of these processes or a combination thereof may be employed.
The cryogenic expansion process is now generally preferred for removing heavy hydrocarbons from natural gas because it provides maximum simplicity with ease of startup, operating flexibility, good efficiency, safety, and good reliability. U.S. Pat. Nos. 3,292,380; 4,061,481; 4,140,504; 4,157,904; 4,171,964; 4,185,978; 4,251,249; 4,278,457; 4,519,824; 4,617,039; 4,687,499; 4,689,063; 4,690,702; 4,854,955; 4,869,740; 4,889,545; 5,275,005; 5,555,748; 5,566,554; 5,568,737; 5,771,712; 5,799,507; 5,881,569; 5,890,378; 5,983,664; 6,182,469; 6,578,379; 6,712,880; 6,742,358; 6,915,662; 6,945,075; 7,010,937; 7,191,617; 7,204,100; 7,210,311; 7,219,513; 7,565,815; 8,590,340; reissue U.S. Pat. No. 33,408; and co-pending application Ser. Nos. 11/430,412; 11/839,693; 12/206,230; 12/487,078; 12/689,616; 12/717,394; 12/750,862; 12/772,472; 12/781,259; 12/868,993; 12/869,007; 12/869,139; 12/979,563; 13/048,315; 13/051,682; 13/052,348; 13/052,575; and 13/053,792 describe relevant processes (although the description of the present invention in some cases is based on different processing conditions than those described in the cited U.S. Patents and co-pending applications).
The present invention is a novel means of removing heavier hydrocarbon components from natural gas that combines what heretofore have been individual equipment items into a common housing, thereby reducing the plot space requirements, the capital cost of the plant, and (more importantly) the capital cost of the associated platform or ship. In addition, the more compact arrangement also eliminates much of the piping used to interconnect the individual equipment items in traditional plant designs, further reducing capital cost and also eliminating the associated flanged piping connections. Since piping flanges are a potential leak source for hydrocarbons (which are volatile organic compounds, VOCs, that contribute to greenhouse gases and may also be precursors to atmospheric ozone formation), eliminating these flanges reduces the potential for atmospheric emissions that may damage the environment.
In the following explanation of the above figures, tables are provided summarizing flow rates calculated for representative process conditions. In the tables appearing herein, the values for flow rates (in moles per hour) have been rounded to the nearest whole number for convenience. The total stream rates shown in the tables include all non-hydrocarbon components and hence are generally larger than the sum of the stream flow rates for the hydrocarbon components. Temperatures indicated are approximate values rounded to the nearest degree. It should also be noted that the process design calculations performed for the purpose of comparing the processes depicted in the figures are based on the assumption of no heat leak from (or to) the surroundings to (or from) the process. The quality of commercially available insulating materials makes this a very reasonable assumption and one that is typically made by those skilled in the art.
For convenience, process parameters are reported in both the traditional British units and in the units of the Systeme International d'Unités (SI). The molar flow rates given in the tables may be interpreted as either pound moles per hour or kilogram moles per hour. The energy consumptions reported as horsepower (HP) and/or thousand British Thermal Units per hour (MBTU/Hr) correspond to the stated molar flow rates in pound moles per hour. The energy consumptions reported as kilowatts (kW) correspond to the stated molar flow rates in kilogram moles per hour.